Exploration of gas fields can involve discovery of wells that contain significant quantities of hydrogen sulfide and other organic and inorganic sulfur compounds. Oil, natural gas, and water with a high concentration of sulfur compounds such as hydrogen sulfide and sulfur dioxide are referred to as “sour.” Hydrogen sulfide is a colorless, toxic, flammable gas that is responsible for the foul odor of rotten eggs. It often results when bacteria break down organic matter in the absence of oxygen, such as in swamps, and sewers alongside the process of anaerobic digestion. It also occurs in volcanic gases, natural gas and some well waters. Sour oil and sour water are not only undesirable as sour products are economically useful, they can be extremely toxic and deadly because high levels of sulfur and sulfur byproducts. For example, hydrogen sulfide is a highly toxic and extremely deadly gas. The industry considers oil or water containing 100 parts per million (“ppm”) (0.01%) sulfur sour oil and sour water. Although this is the minimum level, oil wells and water can contain higher amounts. Oil and water can contain hydrogen sulfide up to 300,000 ppm (30%) at the immediate gas/liquid interphase, the vapor space in a tank or container, and the atmosphere surrounding a spill. At higher concentrations, hydrogen sulfide is toxic and deadly.
As used herein, the term “sour oil” refers to oil containing levels of hydrogen sulfide in an amount greater than 100 ppm (0.01%). Sour oil can also mean oil containing 0.5% or more sulfur by weight. The term “sour water” refers to water containing hydrogen sulfide in an amount greater than 100 ppm (0.01%). The terms “sweet,” “sweetened,” and/or “sweetening” mean a product that has low levels of hydrogen sulfide, has had hydrogen sulfide removed, or the process of removing hydrogen sulfide. The term “stripping” means removing hydrogen sulfide from water and/or oil. The terms “acceptable limits” or “acceptable amounts” or “acceptable levels” refer to the maximum amount of hydrogen sulfide allowed according to any of the pertinent regulations. For example, the Environmental Protection Agency (“EPA”) has certain regulations regarding the concentration of hydrogen sulfide that may be released into the environment. Furthermore, the Occupational Safety and Health Administration (“OSHA”) provides certain regulations on the amount of hydrogen sulfide one may be exposed to without being considered a health hazard. There may be other regulations that apply, such as state regulations. The terms “acceptable limits” or “acceptable amounts” or “acceptable levels” can also refer to the maximum amount of hydrogen sulfide allowed in oil and/or water in order for a facility to accept the materials.
Exploratory and developmental wells with high concentrations of hydrogen sulfide, far away from hydrogen sulfide removal facilities present a problem of transporting the sour water and sour oil. Both liquids must be transported by truck, sometimes long distances over public and private roads. In most cases, sour water, which is dangerous to transport, will also not be accepted by most re-injection facilities if it contains more than a trace amount of hydrogen sulfide.
Similarly, sour oil, which is also dangerous to transport, will not be accepted by most refineries or pipeline hubs, if it contains more than a trace of hydrogen sulfide. If one finds a facility willing to accept liquids with a high concentration of hydrogen sulfide, odds are they are hundreds of miles away from the exploratory well. A truck accident or a simple leak could endanger the transportation crew, as well as the public.
There are other problems downstream in the transportation of sour oil as well. For example, transport from the exploratory well to a treatment site is usually only the first step in the process. The oil typically has an end destination, whether it is another refinery, a distributer, or a consumer. Any contamination by hydrogen sulfide along the way would create a safety and environmental hazard. One example can be seen in transportation of oil that is obtained through a fracturing or “fracking” process. Oil extracted through the fracking process typically is sweet and contains little hydrogen sulfide. This oil has to be transported from the site to its end destination. The transportation can be hindered, however, if there is an upstream contamination of hydrogen sulfide of the shipping vessels or oils with different grades are mixed for shipping.
Rail shipment of crude oil has become an option for moving oil out of high production areas with little pipeline access. The shipping industry is adversely affected by having to address the shipping of hydrogen sulfide. The solution to rail safety issues are typically unanticipated costs, including rail car investments or new safety protocols to address the shipping of sour oil.
For example, an oil-loading rail terminal in North Dakota may be forced to shut down its facility unless the amount of hydrogen sulfide in crude oil delivered to the facility can be reduced. The oil-loading rail terminal requested the Federal Energy and Regulatory Commission (FERC) to restrict the amount of hydrogen sulfide in crude deliveries, after a large concentration of hydrogen sulfide was discovered a tank at an upstream facility. The terminal requested a limit of 5 ppm hydrogen sulfide. Another company objected to the request, as it ships crude oil to the terminal. In response, the terminal asserted that without the new limits to hydrogen sulfide coming to its facility, its employees who stand on top of rail tankers to pump crude could be exposed to harmful vapors. The terminal further argued that if higher levels were allowed to be delivered to its terminal, other terminals downstream would have to shut down its rail facility.
Even if the sour water and sour oil is treated to remove hydrogen sulfide content through conventional methods of using scavengers or other treating chemicals, facilities will not accept the treated water or oil if it contains too much of the treatment chemicals. This is especially problematic with wells containing high levels of hydrogen sulfide that require more of the treatment chemicals to remove the hydrogen sulfide concentrations.
Moreover, many regulations are in place regarding the treatment and disposal of sour oil and sour water. For example, in order to vent undesirable sour water, there has to be less than 10 ppm (0.001%) of hydrogen sulfide vented into the open air according to OSHA regulations. Burning sour oil quickly reaches the emission limits per site. For example, common limits for sulfur emissions are between 100 tons and 250 tons of sulfur. In order to achieve these lower concentrations, the industry has typically used methods involving the use of reducing sulfur content using chemical catalysts that remove sulfur. These are typically liquid hydrogen sulfide scavengers added to the water or oil to absorb the hydrogen sulfide and prevent it from becoming vapor. This solution is feasible and affordable where there is a low concentration of hydrogen sulfide in the water or oil. Once the gas product of the well gets much over 5000 ppm (0.05%), the oil and water will contain amounts of hydrogen sulfide such that liquid scavengers become very expensive. With wells approaching or exceeding 10,000 ppm (1%) hydrogen sulfide, the cost of using liquid scavenger on the oil and water products exceeds the value of the oil itself after transportation costs.
For example, a well with an average of 30,000 ppm (3%) hydrogen sulfide in its gas product, 40,000 ppm (4%) in the vapor space of its water tanks and 60,000 ppm (6%) in the vapor space of its oil tanks might easily cost $20 per barrel of water and $40 per barrel of oil to use hydrogen sulfide scavengers to treat those liquids so that they are safe for transportation. Even then, it takes a special refinery to be able to accept oil such high concentrations of the scavenger materials.
Furthermore, the liquid scavengers appropriate for water and oil are themselves very noxious chemicals. Workers dealing with these chemicals must wear full HAZMAT suits. And, if there is a spill of the scavenger chemicals at any point during transportation, it again poses a threat to the safety of the public and the transport personnel.
Sour oil and sour water high in hydrogen sulfide is extremely toxic and rapidly deadly. Hydrogen sulfide is lethal if inhaled in concentrations down to 1000 ppm (0.1%) in air or water or oil vapor. At low concentrations, hydrogen sulfide has a characteristic odor similar to the smell of rotten eggs. At higher concentrations, the typical rotten egg odor is lost, as hydrogen sulfide can fatigue the sense of smell.
Hydrogen sulfide is a very toxic gas at normal temperatures. It poses a very serious inhalation hazard. There is a large amount of information on human exposures. However, in most cases, the exposure levels and exposure durations are unknown or crudely estimated. Effects at various exposure levels are believed to be as follows: 0.001-0.13 ppm—odor threshold (highly variable); 1-5 ppm—moderately offensive odor, possibly with nausea, or headaches with prolonged exposure; 20-50 ppm—nose, throat and lung irritation, digestive upset and loss of appetite, sense of smell starts to become “fatigued”, odor cannot be relied upon as a warning of exposure; 100-200 ppm—severe nose, throat and lung irritation, ability to smell odor completely disappears; 250-500 ppm—potentially fatal build-up of fluid in the lungs (pulmonary edema) in the absence of central nervous system effects (headache, nausea, dizziness), especially if exposure is prolonged; 500 ppm—severe lung irritation, excitement, headache, dizziness, staggering, sudden collapse (“knockdown”), unconsciousness and death within 4-8 hours, loss of memory for period of exposure; 500-1000 ppm—respiratory paralysis, irregular heartbeat, collapse, and death. It is important to note that the symptoms of pulmonary edema, such as chest pain and shortness of breath, can be delayed for up to 48 hours after exposure.
Prolonged exposure (for several hours or days) to concentrations as low as 50-100 ppm can cause a runny nose, cough, hoarseness, and shortness of breath. Prolonged exposure to higher concentrations can produce bronchitis, pneumonia and a potentially fatal build-up of fluid in the lungs (pulmonary edema). There are numerous case reports of deaths, especially among workers in the petroleum, sewage treatment, and agricultural industries. Most fatalities have occurred in relatively confined spaces (e.g. sewers, sludge tanks, cesspools, or hydrogen sulfide collecting in pits or dips on open land or in buildings). In many cases, multiple deaths have occurred at a single site. Rescuers, attempting to save an unconscious co-worker, have entered a hazardous and/or confined area without respiratory protection or safety lines. They, in turn, have been overcome by hydrogen sulfide.
Workers who survive a serious short-term hydrogen sulfide exposure may recover completely or may experience long-term effects. Nervous system and respiratory effects have been described in small human population studies or case reports. Permanent or persistent nervous system effects have included fatigue, anxiety, irritability, intellectual decline, reduced attention span, impaired learning and memory, altered sense of smell, and motor deficits. Some of the nervous system effects may be due to a lack of oxygen reaching the brain cells during a severe hydrogen sulfide exposure. Respiratory effects have included symptoms (shortness of breath upon exertion, chest tightness or wheezing) consistent with hypersensitivity of the airways (Reactive Airways Dysfunction); permanent lung damage (pulmonary fibrosis) and significant reductions in residual volume (one measure of lung function).
Although cyanides are better known to the general public to invoke thoughts of deadly poisons and toxicity, hydrogen sulfide are just as deadly. For example, incidents involving the deadly nature of hydrogen sulfide are well documented. One example involved the death of nine people in Texas who were killed by gases leaking from an unattended carbon dioxide injection system designed to extract oil from a well in Texas. Eight of the victims were in a house 100 yards from the well.
In another example involving transportation of hydrogen sulfide, two Michigan employees drove a tank truck to a sour oil well tank farm to obtain waste brine. When they failed to get a flow of brine from a ground level connection just outside the tank farm dike, they proceeded to the brine tank. One employee went to the top of the tank, which was 13 feet above the ground. He yelled a warning, but was instantaneously overcome by escaping hydrogen sulfide-rich gas. He was later found dead on the platform beside the top of the tank. The other worker waiting near the top of the stairs was overcome and collapsed before he could retreat. Fortunately, he fell down the stairway out of the area of contamination and regained consciousness. The hatch that had been opened was upwind of the access platform and about two feet above it. Clearly, it is beneficial to have a simple, economic, and effective way to reduce the level of hydrogen sulfide from materials in order to improve safety at exploratory sites and safety in the transportation of materials.
In addition to the health hazards due to exposure to hydrogen sulfide, hydrogen sulfide is a flammable gas that creates additional transportation hazards. Recently, 47 people died when a freight train transporting crude oil caught on fire when it wrecked. The composition is under investigation, as crude oil typically does not explode. Contamination of the shipment with hydrogen sulfide from an upstream source is being considered a culprit to why the freight train exploded unexpectedly. Certain embodiments of the present invention address the safety concerns with shipping oil containing hydrogen sulfide and can prevent contamination of otherwise less hazardous oil.
Other current methods to remove hydrogen sulfide involve the use of use natural gas to remove sulfur, or use specialized apparatus that use amine to remove sulfur. The majority of processes to sweeten oil involve absorption of hydrogen sulfide in an amine solution, use of a carbonate process, use of solid bed absorbents and physical absorption. For example, U.S. Patent Publication No. 2012/0111769 to Hassan et al. (“Hassan”), incorporated in its entirety by reference, describes a method where the sour oil is subjected to a high shear and at least one desulfurizing agent wherein the desulfurizing agent is selected from a group consisting of bases and inorganic salts to produce a high shear stream and separating the sulfur rich product and sweetened oil product from the high shear-treated stream. Hassan further describes a system and a method that use a shearing mechanism in combination with chemicals or other gases to remove sulfur. According to the Hassan system and method, one needs high shear and at least one chemical desulfurizing agent.
U.S. Pat. No. 8,216,520 issued to Choi et al. and Patent Publications Nos. 2011/0147266, 2009/0173664 and 2011/0315600 also by Choi et al. (collectively “Choi”), all incorporated by reference in their entirety, involves a system, method, and apparatus for upgrading heavy oil. Choi describes a system and method that involves combining heavy oil with a water feed in a mixing zone to form a heavy oil/water mixture, wherein the mixture does not exceed 150 degrees Celsius; subjecting the oil water mixture to ultrasonic waves to create a submicromulsion; pumping the submicromulsion using a high pressure pump to increase the pressure to or above the critical pressure of water; and heating the submicromulsion between 150 degrees C. and 350 degrees Celsius. Choi further describes adding a heated oxidant stream to the heavy oil/water mixture wherein the heated oxidant stream is at a temperature and pressure that exceeds the critical temperature and pressure of water; introducing the mixture into a zone essentially free of an externally-provided catalyst wherein the reaction is subjected to conditions that exceed the supercritical conditions of water such that a portion of hydrocarbons in the reaction mixture undergoing cracking to form an upgraded mixture. Furthermore, the Choi process requires subjecting the mixture to ultrasonic waves.
The Choi process requires a special apparatus that has a mixing zone to combine heavy oil with a water feed at a slightly elevated temperature to create a heavy oil/water mixture, where the mixing zone is an ultra-sonic wave generator; a pre-heating zone that is fluidly connected with the mixing zone, operable to heat the heavy oil/water mixture to a temperature up to about 350 degrees Celsius; a high pressure pumping means, operable to increase pressure of the heavy/oil water mixture to at least the critical pressure of water; and a reaction zone that is essentially free of an externally provided catalyst and an externally-provided hydrogen source fluidly connected with the pre-heating zone and able to withstand the temperature of the critical temperature of water and being able to withstand the pressure in excess of the critical pressure of water. The result is an upgraded oil with reduced amounts of substances such as sulfur.
The Choi process, although describing a system and method essentially free of external catalysts or external hydrogen to remove compounds including sulfur compounds, requires heating oil and water, mixing the water with an ultrasonic component, a high pressure system to bring the mixture to the critical pressure of water. Choi teaches away from a system and method that can remove sulfur byproducts, such as hydrogen sulfide, from sour oil without complex equipment and a highly controlled environment.
U.S. Pat. No. 4,253,928, issued to Blytas et al. (“Blytas”) describes a method of sour water treatment in which sour water components are removed from a sour water stream in an electrodialysis step in which the sour water stream becomes the dilute stream. The Blytas process subjects a sour water stream to an electrodialysis step in which the acidic component and the basic component of the stream migrate from the stream through a fixed anion and cation exchange membrane to one or more concentrate streams, and steam strip the concentrate streams in order to remove the volatile acidic component and the volatile basic component. Blytas is incorporated by reference in its entirety. This method is geared toward a pre-process, upstream of an unspecified steam-stripping process. It uses electrodialysis which requires complex mechanical and process parameters not suitable for field use due to cost and portability. For example, Blytas uses a membrane to remove sour components from water. This is a pre-process treatment and does not address hydrogen sulfide vented in the steam process with regard to safely breathable concentrations. The present invention is devoid of the use of a membrane to remove hydrogen sulfide from sour water. Furthermore, the present invention does not require a steam-stripping process.
Other methods of removing hydrogen sulfide from water involve using a high voltage electrooxidation. U.S. Patent Publication No. 2012/0273367, by Themy et al. (“Themy”) removes hydrogen sulfide through the use of electrooxidation. Themy is incorporated by reference in its entirety. Hydrogen sulfide is present as the part of hydrocarbon streams typical of petroleum recovery sources. Accordingly, hydrogen sulfide can contaminate various water sources and wastewater streams, including those from hydraulic fracturing operations. Hydrogen sulfide is corrosive and renders some steels brittle, leading to sulfide stress cracking, which is a concern in many applications, particularly when handling acid gas and sour crude oil in the oil industry. Thus, removal of hydrogen sulfide is desirable in the art. The primary method used in the art of removing hydrogen sulfide is the Claus process, which proceeds according to Formula 2H2S+O2→2S+2H2O. Other current technology available to remove hydrogen sulfide includes high pressure oxygenation of hydrogen sulfide solutions and oxidations with ozone and hydrogen peroxide. Therefore, the water purification systems and methods may also be useful for removing hydrogen sulfide from a water source. According to Themy, the electrooxidation cocktail removes hydrogen sulfide not only by oxidizing hydrogen sulfide to elemental sulfur or sulfur-containing anions (e.g., SO3−, SO42−), but it also destroys sulfide reducing bacteria (SRB), which may be responsible for production of the hydrogen sulfide in some wastewater sources in the first place. Furthermore, some sulfur-containing organic compounds may be oxidized by the electrooxidation cocktail to reduce their odor (e.g., thioethers oxidized to sulfoxides or sulfones), and further oxidation of the hydrocarbon portion of these molecules may take place as set forth Themy to remove them from the purified wastewater.
U.S. Patent Publication No. 2013/0312974, by McClung IV et al. (“McClung”) describes treating a well with a material to inhibit hydrogen sulfide producing bacteria. McClung describes adding an inhibitor to a treatment fluid. The treatment fluid is added to a source containing bacteria that produces hydrogen sulfide to inhibit the growth of the bacteria. McClung is incorporated by reference in its entirety.
By way of providing additional background, context, and to further satisfy the written description requirements of 35 U.S.C. §112, the following references are incorporated by reference in their entireties for the express purpose of explaining the nature of the oil and gas industry and methods to further describe the various systems, sub-systems, tools and components commonly associated therewith: U.S. Pat. No. 4,218,309, issued to Compton, U.S. Pat. Nos. 4,447,330 and 4,536,293 issued to Babineaux, III, Japanese Patent Publication No. 2008055291, invented by Mashahiko et al., Chinese Patent No. 101532380 issued to Zhengguo.
The process to remove the sulfur content from sour water also requires specialized equipment, as sour water has corrosive properties. Using air to remove hydrogen sulfide, or “aeration,” as a unit operation depends on two basic principles: equilibrium conditions and mass transfer considerations. The water to be treated is in equilibrium chemically with its component species and physically in equilibrium with the atmosphere above the water surface. These equilibrium conditions define the limits of the gas transfer process. Aeration is an effective removal mechanism because hydrogen sulfide exists as a dissolved gas in some water. Incidentally, the function of aeration is not specifically to oxygenate the water; rather it is to strip the dissolved gas (hydrogen sulfide) out of the water by changing the equilibrium conditions of the water and thus drive the dissolved gas out.
The removal of hydrogen sulfide by air stripping is defined by application of Henry's Law. Henry's Law, however, is generally associated with dilute solutions. Henry's Law relates the concentration of a gas in the water to the partial pressure of the gas above the liquid. It is recalled that partial pressure is pressure that a particular gas exerts as it moves toward equilibrium. Equilibrium occurs as gasses flow from regions of higher partial pressure to regions of lower pressure. The larger this difference, the faster the flow. Hydrogen sulfide exists in equilibrium in three different forms as shown in the reactions below with their respective pK (disassociation) values.H2S═HS−+H+ pKa=7.1HS−═S2−+H+ pKa=14
Certain facilities prohibit air stripping because of the potential combustible off gases and the costly residual air incineration, where the current processes in use teach away from using air to strip sour water. Importantly, traditional processes of using air to strip sour water are used primarily on sour water with very low contaminant concentrations.
While it is known that air can potentially be used to strip water, the majority of current processes use specialized equipment, complicated processes, or use natural gas or other materials to remove high levels of hydrogen sulfide. For example, Japanese Patent No. 2008307475A, issued to Kyoji et al. (“Kyoji”), describes an apparatus and method to remove hydrogen sulfide from groundwater. Kyoji is incorporated by reference in its entirety. According to Kyoji, the preferred embodiment of the apparatus uses a pump to pump ground water into a storage tank. A pipe applies air to the water in the storage tank, releasing hydrogen sulfide in a gas phase. The gas phase is then sent to a separate desulfurizing compartment that contains a desulfurizing agent such as iron oxide or activated carbon. Air is then vented from the desulfurizing compartment. The water is then sent to a separate tank where the water is processed to remove any suspended matter or precipitate in the remaining water. The water is then discharged after treatment in the separate water treatment tank. Kyoji requires a separate compartment from which air is vented to contain a desulfurizing agent, such as a chemical catalyst. Although Kyoji mentions that certain embodiments of the apparatus do not contain a separate desulfurizing compartment, it is unclear if Kyoji's alternate embodiment would vent air directly from the compartment containing the sour water. Such alternate embodiment does not account for human safety or environmental safety. Thus, Kyoji does not disclose a separate compartment, devoid of any catalysts or additional desulfurizing agents, where the concentration of hydrogen sulfide is measured before it is vented to ensure the concentration of hydrogen sulfide is within the acceptable limits.
European Patent Application Publication No. 2495219 (“EP '219”) describes a method for removing contaminants from feedwater. EP '219 is incorporated by reference in its entirety. EP '219 describes a method that includes forming a dispersion of bubbles of a treatment gas in a continuous phase comprising feedwater, wherein the bubbles have a mean diameter of less than about 5 micrometers, and the gas is selected from air, oxygen, and chlorine. The gas bubbles have a mean diameter of less than 1 micrometer, or no more than 400 nanometers (“nm”). In the method described in EP '219, the feedwater and treatment gas mixture and the continuous phase is subjected to a shear rate of greater than about 20,000 s−1. The treatment gas and the continuous phase are contacted in a high shear device, wherein the high shear devices comprises at least one rotor, and wherein the at least one rotor is rotated at a tip speed of at least 22.9 meters/second (4,500 feet/minute) during formation of the dispersion. The high shear device produces a local pressure of at least about 1034.2 MPa (150,000 pounds per square inch, “psi”) at the tip of one rotor during the formation of the dispersion. The energy expenditure of the high shear devices during the formation of the dispersion may be greater than 1000 W/m3. The dispersion is introduced into a vessel and particle containing water is extracted from the vessel. The particle containing water is then introduced into a separator. This method uses a specific mechanical device with very specific mechanical and process parameters to remove hydrogen sulfide and other contaminants from water. While its advantages (may be contained in a small footprint, may result in water suitable for direct disposal into surface lakes, streams or municipal water facilities, seems a fast process) appear useful in other work environments, they are not needed for produced water transportation or disposal in remote or field oil and gas production scenarios. Also, the advantages come at a greater cost not suitable for field use because the method uses a specific mechanical device with very specific mechanical, power use and process parameters and it vents hydrogen sulfide and where chlorine gas is used a further possibly toxic, non-breathable mixture without regard to safely breathable concentrations.
In order to provide additional background information and further comply with disclosure requirements, the following documents are incorporated by reference herein: U.S. Pat. No. 9,005,432 entitled “Removal of Sulfur Compounds from Petroleum Stream” filed Jun. 29, 2010; U.S. Pat. Appl. Publ. No. 2015/0093314 entitled “Absorbent Composition for the Selective Absorbtion of Hydrogen Sulfide and Process of Use Thereof” published Apr. 2, 2015; Sour Water Strippers Exposed, by Ralph H. Weiland and Nathan A. Hatcher, presented at Laurence Reid Gas Conditioning Conference, Norman Okla., Feb. 28, 2012; and Partitioning of Hydrogen Sulphide in Wellstream Fluids, by CAPCIS, CAPCIS Limited, UK.
Other known aeration processes to remove hydrogen sulfide from water are unsuited for removing high levels of hydrogen sulfide as those encountered at exploratory sites. For example, certain processes have materials containing hydrogen sulfide exposed to the open environment. This is problematic when materials have high levels of hydrogen sulfide, as the hydrogen sulfide escaping into the open environment is toxic and hazardous. Certain embodiments of the present invention comprise an enclosed environment for the materials containing hydrogen sulfide to prevent high concentrations of hydrogen sulfide to be released into the open environment.
Other processes use catalysts to strip sour water. U.S. Pat. No. 4,784,775 issued to Hardison (“Hardison”) discusses a system to remove hydrogen sulfide from sour water using an aqueous chelated polyvalent metal solution as a catalyst. The present invention removes hydrogen sulfide from sour water without the need of a chemical catalyst.
Known sour water treatment processes are complex and have other disadvantages, such as requiring meticulous process parameters. The present invention is novel and improves on the prior art because the only parameter that must be closely monitored is the concentrations of hydrogen sulfide in the air space that is eventually vented into open air. The present invention can be implemented with very minimal parameters. Deviations in the described process may affect the overall time of the process or efficiency. However, as those skilled in the art can recognize, deviations have little impact on the efficacy of the invention. For example, in certain embodiments, perforations in the diffusion bar located in a tank containing sour water can be 0.25 inches in diameter. In other embodiments, the perforations can be as small as 0.05 inches in diameter. In yet other embodiments, the perforations can be 1.00 inches in diameter. The present invention provides a simpler way to remove hydrogen sulfide such that no automation is required. Although no automation is required for the present invention, certain embodiments include automation. Any parameters described in certain embodiments are not intended to limit the scope of the invention in any way and are only provided as an example to illustrate the novelty and improvements of the present invention over the prior art.
Present methods of sweetening oil and stripping sour water is cost restrictive, and only becomes economical when performed in large scale. Building such facilities is impractical at exploratory sites. The present invention, can be performed at any scale, using no more than items and equipment that would already be at the exploratory site and other items readily obtained from a local hardware store such as Lowe's or Home Depot.
Treatment facilities can be inaccessible to those who are performing exploratory drilling. Furthermore, the equipment and materials required to perform traditional processes are not cost effective at exploratory sites. Those working at remote exploratory sites do not have access to the resources needed to sweeten sour oil or sour water. For example, many of the typical processes use sweet natural gas to sweeten oil or to sweeten water. Often, a source of sweet natural gas is not readily available, and it is not economical to sweeten sour natural gas in order to use to treat sour oil or sour water.
Due to the remote nature of exploratory facilities, the toxic and deadly materials must be transported significant distances to a treatment facility. Anyone involved in the transportation is subject to the potential hazards of hydrogen sulfide, as well as the potential environmental disaster that could occur if something happens along the way from the remote well site to the treatment facility.
Certain embodiments of the invention provide a system and method to sweeten sour oil and water without a need to use hydrocarbons or other catalysts. This is especially useful in the exploratory gas industry when access to traditional methods used to sweeten oil and water are not readily available and could be many miles away. Certain embodiments include a system and a method that comprise collecting the sour oil in a container, maintaining the sour oil in an air-free environment, adding water, and agitating the mixture. Other embodiments of the present invention include using sour water to remove hydrogen sulfide from sour oil.